1. Field of the Invention
This invention relates to apparatus and methods for cooling large vessels and the contents thereof. While the scope of the invention encompasses any type of vessel, broadly referred to as a “process vessel,” the invention has particular applicability to large vessels used in industrial applications, namely in process units, including but not limited to hydroprocessing reactors such as hydrotreaters, hydrocrackers, and catalytic reformers having voluminous beds of catalyst therein, etc. As described in more detail below, at periodic intervals such vessels must be cooled, from their normal operating temperature to a much lower temperature, typically near ambient temperature, in order to permit entry into the vessels for replacement of the catalyst beds therein. The work period during which the catalyst is replaced is commonly known as a “turnaround.”
Hydrotreaters, hydrocrackers, and catalytic reformers are crucial for processing or producing distillate products (e.g., gasoline, jet fuel, diesel, or feeds to downstream units such as catalytic crackers) from crude oil in order to meet numerous product quality specifications, chief among them being organic sulfur and nitrogen content. For hydrotreaters, for example, as allowable sulfur limits have been tightened (e.g., for ultra-low sulfur diesel, ULSD), the processing requirements have become more severe. A hydroprocessing reactor contains large amounts of catalyst through which the untreated feed stream, mixed with hydrogen and other light gases, flows at high temperature and pressure. This enables converting the sulfur and other impurities present in the feed stream into hydrogen sulfide, ammonia, etc., which are then removed in downstream processing facilities. Also, some fraction of the feed may be converted into lighter fractions when hydrocracking reactions occur.
After some period of operation, typically two to five years, the catalyst in process vessels such as hydrotreaters, hydrocrackers, and catalytic reformers is “spent” and must be replaced. This requires the vessel (unit) to be brought down or taken out of service for a turnaround, during which catalyst replacement and other maintenance and repair activities are carried out. The duration of the turnaround must be minimized to avoid excessive economic losses from the production outage. A key requirement during the turnaround is to cool the process vessel to ambient temperature so that the catalyst can safely be unloaded and replaced, and entry into the vessel becomes feasible for other maintenance-related repairs.
FIG. 1 shows an exemplary prior art arrangement of a typical process system or processing unit, for example a hydrotreater system 10, comprising a process vessel (e.g. hydrotreater reactor) 100; in-place compressor, namely a hydrogen recirculating compressor or recycle gas compressor 110; and a piping system, generally referred to as piping system 120, forming multiple flow loops or flow paths in the system, commonly referred to as the “reactor loop.” As known in the art, during normal product processing, unit feed (e.g. crude oil) is supplied to piping system 120 (piping system 120 referring generally to the collection of piping shown in the figures) at a point downstream of recycle gas compressor 110 (as shown in FIG. 1), where it joins a makeup hydrogen stream and a recycle gas stream moved by recycle gas compressor 110; the combined stream flows through flowline 123 to process vessel 100. The combined stream exits process vessel 100, and typically flows through one or more effluent coolers 150 (one or more of which are part of the feed preheat train) and a flash vessel or separator 160. Liquid product exits separator 160 as shown (for further handling and/or processing), and recycle gas exits separator 160 and returns to recycle gas compressor 110. Gas removal (purge) is noted in FIG. 1. This purge stream removes pollutants and other components from the recycle gas.
In addition to the product/recycle gas flow loop, known installations usually comprise other elements. One or more isolation valves 130 may be disposed in the recycle gas flowline and, after preheat exchangers 150 (which pick up heat from the reactor effluent), a fired heater 140 permits heating of the combined feed/make-up hydrogen/recycle gas streams. One or more alternate recycle gas (typically hydrogen-rich) injection points into lower beds of process vessel 100 are typically provided, for example through flowlines 190, 200 and 300, collectively referred to as quench flowlines, as shown. It should be understood that, during normal operation of the unit, the primary purpose of quench flowpaths 190, 200 and 300 is to enable unheated recycle gas, discharged from recycle gas compressor 110, to be introduced into the top of each catalyst bed in process vessel 100 in the event that temperature in any portion of that bed exceeds a pre-determined maximum. Accordingly, flow of unheated recycle gas through quench flowlines 190, 200, and 300 is generally intermittent. Note that each of quench flowlines 190, 200, and 300 further comprise bypass flowlines and valves as follows: quench flowline 190, comprising valves 20, 30 and 40, and bypass line 52, comprising valve 50; quench flowline 200, comprising valves 210, 220, and 230, and bypass line 250, comprising valve 240; and quench flowline 300, comprising valves 310, 320 and 330, and bypass line 350, comprising valve 340. It is understood that other arrangements of quench piping and valves are possible.
Note that some of the reactor effluent coolers 150 are used typically to preheat the feed to furnace 140 (the piping to do so not shown for clarity), and may additionally incorporate air- or water-cooled exchangers, prior to separator 160. Fluid flow directions are indicated by arrows in FIG. 1. Other inputs/products to the system are noted in the drawings, in particular FIGS. 1-4 and FIG. 6.
2. Prior Art Process Vessel Cooldown Process
Hydrotreater, hydrocracker and catalytic reformer reactors are very large process vessels that can weigh as much as a million pounds or more; additionally, they contain a catalyst inventory approaching a million pounds or more. As can readily be understood, the process reactor vessel, referred to generally herein as “process vessel,” and its catalyst inventory contain a tremendous amount of thermal energy (heat) during normal operation. Generally, following cutoff of unit feed and makeup hydrogen, and shutdown of furnace 140, process vessel cool-down has required many days, and this has traditionally been carried out in two phases as follows:
(a) Phase I, comprising a fairly rapid reduction in temperature from a first operating temperature of c. 500 to 800° F. to an intermediate temperature of around 200-250° F., using available in-line cooling facilities. This phase I cooling is typically carried out by circulating hydrogen through the process vessel by use of the recycle gas compressor, and using any existing cooling facilities in the flow loop to cool the recirculating flowstream. Significant limitations exist with this method. The available cooling is of limited thermal capacity, and as it uses the surrounding environment as the energy sink and, therefore, cannot achieve a final temperature lower than ambient. In practice, this final temperature is significantly higher than the ambient temperature, and is typically around 150-250° F., depending on ambient air temperature and system design. Once this temperature range is reached, the cooling curve flattens out and the cooling rate (using only the existing air and/or water cooled exchanger) becomes unacceptably slow, so that Phase II is entered, as below, to enable further reducing the reactor temperature to a value that would be safe for entry by maintenance personnel.
(b) Phase II, comprising a cool-down phase from an intermediate temperature of around 150-250° F. to a second or final temperature, typically around 80-100° F., which in the past has commonly been carried out using injection of purchased liquid nitrogen that is either vaporized prior to injection or injected directly as a liquid into the reactor inlet, with the effluent gases from the hydroprocessing reactor being flared. It is this cold injected nitrogen stream, normally flared upon exiting the reactor vessel, that removes heat from the process vessel. It should be noted that chilled air cannot be injected instead of nitrogen because the catalysts typically used in such reactors (which may even be pyrophoric) cannot be exposed to oxygen for reasons of safety.
However, the rate of nitrogen injection is limited, (a) by its extremely high cost, (b) by the safety requirements not to overload the flare gas system, (c) the need to avoid diluting flare gas heating value which could result in extinction of the flare flame, and (d) by the requirement not to lower the temperature of metallic piping and other components beyond safe metallurgical limits. As a result, this second cooling phase (Phase II) has traditionally required several days to complete, at significant cost, owing to the slow rate of nitrogen injection and also the loss of production resulting from extended facility downtime, plus the purchase cost of the nitrogen.
In prior art systems, the surrounding environment is the available heat “sink,” and cannot provide sufficient heat extractive capacity to efficiently cool the process vessel to a desired end temperature suitable for personnel entry. Among other reasons the available temperature differential between the ambient temperature and the temperature of the hot reactor effluent is too small.
Accordingly, there is a great economic incentive to shorten the Phase II cool-down cycle, thus enabling the process vessel and associated processing unit to be restored to full production rates in a shorter time. In addition, avoidance of the nitrogen-related costs would result in significant savings.